This invention relates to a method of restoring the permeability of an underground hydrocarbon formation. More particularly, the invention concerns injecting multiple aqueous solutions of acid and chlorine dioxide to restore permeability to a formation interval near the wellbore where permeability has been reduced by polymer residue and biological material.
The use of surfactants and polymers in enhanced oil recovery techniques allows significant improvement in petroleum recovery. However, such systems can damage formation permeability due to plugging in the wellbore and formation. Even though enhanced oil recovery polymers are water soluble, polymer solutions may deposit polymer in the sand or rock formation adjacent the wellbore, reducing permeability of the formation. Other substances that cause formation plugging are naturally occurring animal and plant life such as algae which may grow and multiply around a wellbore.
A typical enhanced oil recovery process involves the injection of a polymer waterflood or aqueous drive polymer into an injection well and the recovery of petroleum and aqueous fluids from a production well. The aqueous drive fluid contains either biological or synthetic polymeric material and may drive a surfactant slug.
Biological polymeric materials are typically homopolysaccharides, xanthan gum heteropolysaccharides and adducts of these materials which may be used alone or in combination. These polymers are used in molecular weights ranging from about 500,000 to about 10,000,000 or more. Xanthan gum polysaccharides are typical water soluble drive fluid polymers. They may be contaminated with water insoluble, protein debris which will plug injection wells. The method of drive fluid make up can also augment well plugging.
Synthetic polymers include polyacrylamide, polymers containing acrylamide monomer, such as acrylamide-vinyl sulfonic acid copolymers and adducts thereof such as partially hydrolyzed acrylamide or alkoxylated acrylamide. Hydration of polyacrylamides prior to use requires extreme care, and if a polyacrylamide is not properly hydrated, it may plug the rock or sand matrix near the injection well. See U.S. Pat. Nos. 4,217,230; 4,228,016; 4,228,017 and 4,228,018. These polymers range in molecular weight from about 500,000 to about 10,000,000 or more.
Generally, polymer plugging occurs at or near the formation face in the wellbore. The porous formation face acts as a sieve to filter and accumulate insoluble and entrained matter from the aqueous drive fluid. As stated previously, this insoluble matter includes improperly hydrated polymer, protein debris and biological matter which may grow and multiply around the wellbore. After time, the accumulation becomes sufficient to substantially reduce the permeability of the formation to fluid.
Several treating agents have been proposed to alleviate permeability reduction problems. U.S. Pat. Nos. 3,482,636; 3,529,669 and 3,556,221 disclose sodium hypochlorite as a preferred treating agent. Because sodium hypochlorite must be used in alkaline solution, problems can occur with the formation of insoluble precipitates with calcium and magnesium salts. These may also plug formation pores. When such precipitation occurs, it is usually desirable to mix acid with the treating agent to dissolve the precipitate plug. But this is not possible with a sodium hypochlorite solution, because such a solution decomposes to chlorine gas and sodium salt upon acidification.
A method for restoring the permeability of injection wells which have become plugged with residue is described in U.S. Pat. No. 4,464,268. The patent discloses the injection of hydrogen peroxide in an aqueous solution in amounts of about 1% to about 30% by weight, and more preferably about 2% to about 10% by weight of hydrogen peroxide. The solution is allowed to soak in the formation for a period of time to attack and breakup the polymer and biological debris plugging the formation.
Chlorine dioxide is known in the art as an effective anticorrosion agent and a biocide in the oil field. For discussions of chlorine dioxide in corrosion controlled systems, see Canadian Pat. No. 1,207,260: Prues, W. et al., "Chemical Mitigation Of Corrosion By Chlorine Dioxide In Oil Field Waterfloods," Material Performance, Vol. 24, No. 5, pp. 45-50 (May 1985); and Sacco, F. J., "The Use Of Chlorine Dioxide In A Late Life Waterflood," American Chemical Society Petroleum Chemical Division Preprints, Vol. 29, No. 2, pp. 605-6 (March 1984), presented at the American Chemical Society Advances In Oil Field Chemicals and Chemistry Symposium at St. Louis, Apr. 8-13, 1984.
The use of chlorine dioxide as a biocide and a sulfide scavenger is discussed in a product information handout of NL Treating Chemicals entitled "DIKLOR-G Microbiocides/Sulfide Scavenger," Copyrighted April 1987; and Aieta, E. M. et al., "A Review Of Chlorine Dioxide In Drinking Water Treatment," Journal of AWWA, June 1986, p. 62-72.
ChemLink Petroleum Inc. has offered an injection service to oxidize and dissolve deposits that may restrict flow and water injection in disposal wells. This service is called "Easy-Stim" and is designed to remove contaminants such as biomass, iron sulfides, and various types of scale on tubing walls and in perforation slots. This is very briefly discussed in an undated handout entitled "Case History Easy-Stim". Although not mentioned in the handout, it is known that the Easy-Stim process involves the continuous coinjection of chlorine and chlorine dioxide in an overall concentration of 10,000 ppm with normal injection water into a well. The Easy-Stim injection lasts only for about 4 to 6 hours and involved no soaking period until recently in 1988. A soaking period of two hours is now offered.